Common artificial lift systems utilize a system element that is deployed on tubing. For example, electrical submersible systems are deployed or at least partially deployed on tubing. Stators for top-driven progressing cavity pump systems are deployed on tubing. Insertable progressing cavity pumps or reciprocating pumps have tubing deployed seating nipples. Gas lift uses tubing deployed mandrels, etc.
For deep wells, electrical submersible well pumps are typically installed within casing on a string of tubing. The tubing string may be made up of sections of pipe that are screwed together. A motor suspended by the tubing may be supplied with power through a power cable that is strapped alongside the tubing. A pump is normally located above the motor and is connected to the lower end of the tubing. The pump forces fluid through the tubing to the surface.
A centrifugal pump is normally utilized for large pumping volume requirements. The centrifugal pump typically has a large number of stages for moving fluid. In a conventional arrangement, once a centrifugal pump has failed, a costly workover is required wherein the centrifugal pump is retrieved by raising the tubing on which it is suspended.
Another kind of submersible pump is referred to as a progressing cavity pump or PCP. A PCP is suitable for lesser pumping volume requirements or where significant quantities of solids, such as sand and scale, are likely to be encountered. PCPs typically utilize an elastomeric stator defining double helical cavities. The elastomeric stator receives a helical rotor that is rotated therein. The helical rotor may be rotated by a motor located on the surface via a rod that extends down to the pump in the well. Alternatively, the helical rotor may be rotated by a motor lowered into the well with the PCP in an arrangement similar to that of a submersible centrifugal pump.
Another kind of surface-driven PCP installation is known as an insertable PCP. In this type of installation, the pump, stator and rotor are deployed together on rods through the tubing to engage a seating nipple in the tubing string. The rod string is manipulated after seating to free the rotor for normal operation.
When used in harsh environments, it is not uncommon for a PCP to lock-up if the PCP is unable to remove solids that enter the pump. Lock-up can also occur if the pump assembly is shut down since solids in the tubing string tend to settle back down on top of the pump. When pump lock-up occurs in a standard surface-driven PC application, the rod string is pulled from the well with the attached pump rotor. The tubing and pump stator are then flushed and circulated. Once the tubing and pump stator are clean, the pump rotor is lowered on the rod string and reinstalled into the pump stator. The same conditions that lock-up surface driven applications also apply to the bottom drive systems.
One drawback associated with a PCP installed in a conventional PCP arrangement is that a PCP stator may not be removed without performing a costly workover. Further, since the PCP stator is typically deployed on the tubing string, the stator may not be relocated without manipulating the tubing string.
To facilitate deployment of various lift systems within existing well configurations it is desirable to be able to deploy any element without deploying the element on tubing. For example, it is desirable to be able to install PCP equipment using commercially available wireline tooling.
Additionally, it is desirable to be able to relocate a pump within a well in an efficient and low cost manner.